Production of heavy oil and bitumen from a subsurface reservoir can be quite challenging. The initial viscosity of the oil at reservoir temperature prior to any treatment, is often greater than a million centipoise (cP). High viscosity oil cannot be pumped out of the ground using typical methods, and is often mined or processed in situ. Surface mining is limited to reservoirs at depths of less than about 70 meters. The majority of bitumen reserves, however, are present at depths that make surface mining uneconomical. These deeper reserves are typically produced using in-situ recovery methods.
In-situ thermal oil recovery processes such as Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD) are widely used commercial processes for recovering oil from heavy oil/bitumen reservoirs. These thermal processes generally apply heat energy to reservoir using steam or hydrocarbon solvents as the working fluid. As temperature in the reservoir increases, the viscosity of the heavy bitumen (or oil) decreases and the oil is able to flow into a production well.
Steam-assisted gravity drainage (SAGD) is an in situ processing method first introduced by Roger Butler in 1973 as a means of producing heavy oil and bitumen. SAGD involves the use of two parallel and superposed horizontal wells (a well-pair) that are vertically separated by about 5 meters. (See FIG. 1). The SAGD process is roughly described as follows. During the first phase of a SAGD process, sometimes referred to as start-up, steam is circulated between the injector and the producer to establish mobility of fluids between the two wells. Next the production phase of SAGD begins and the steam injection is limited to the injector and oil is produced through the producer. As the steam chamber grows vertically and laterally, viscosity of the bitumen is reduced and the bitumen is drained to the producer below by gravity. Initially, high pressures may be employed, generally around 15 to 20 kPa/meter, to promote vertical development of the steam chamber, which promotes high drainage/production rates. As the steam chamber matures, the pressure of the steam chamber it may be reduced, to help mitigate the rising steam-to-oil ratios caused by heat losses to the overburden/thief zones on top of the reservoir.
As an in situ recovery process, SAGD is very energy intensive largely because the reservoir rock and fluids must be heated enough to lower the viscosity of and mobilize the petroleum. Heat is also lost to over burden and under burden which may contain, water and gas intervals, thus reducing the thermal efficiency of the process. As a result of being energy intensive, SAGD requires a large capital investment in steam generation and water treatment facilities. The operating expense associated with the SAGD process can also be high due to the expense of generating steam and treating produced water. As a result, SAGD is typically operated until the steam-to-oil ratio (and hence the energy intensity) increases to the point where continued operation is either un-economical or otherwise impractical (e.g., incremental recovery from steam injection can no longer be achieved).
Foam has been used in SAGD to block thief zones, decrease channeling, and improved oil displacement during SAGD. Foam is dispersion of gas in a continuous water phase with thin films (lamella), acting as a separator. Given its sensitivity to oil distribution, foam tends to reside in higher permeability layers with less residual oil. Thermally stable surfactants are essential to maintain the foam life because surfactants stabilize lamella by decreasing the water-gas interfacial tension. Li, et al., have reviewed how chemical additives and foam can enhance SAGD performance. Li et al., “Chemical Additives and Foam to Enhance SAGD Performance,” SPE Canada Heavy Oil Technical Conference, 9-11 June, Calgary, Alberta, Canada (2015).
Eventually, every SAGD chamber (which may be an amalgamation of chambers associated with a number of injectors and producers) reaches the point at which economic steam injection operations become impractical. At this point, the SAGD wells are placed in what industry frequently refers to as “blowdown” in which steam injection into the steam chamber typically ceases or is significantly reduced. During blowdown, reservoir pressure must typically be maintained in order to continue producing oil from other locations in the reservoir.
Non-condensable gas (NCG) has been injected by operators to maintain pressure in SAGD operations during mid-late life development stages of SAGD. Meg Energy at their Christina Lake project has co-injected methane with steam as early as at 30% recovery of the drainage area OOIP. Cenovus Energy has performed multiple methane co-injection projects at their Foster Creek and Christina Lake projects. NCG was injected at UTF Phase B, during the wind-down of those wells. Multiple authors have discussed NCG blowdown. See, e.g., Zhao et al., “Numerical Study and Economic Evaluation of SAGD Wind-Down Methods,” Journal of Canadian Petroleum Technology, 42(1): 53-57 (2003).
There is a need to improve SAGD methods during blowdown. Improved SAGD blowdown is required to reduce capital expenses during late stage SAGD operations, improve production from nearby less mature SAGD operations, and improve oil recovery economics including reduced SOR, reduced NCG, and improved thermal efficiency.